Conductor casing for offshore drilling and well completion



, 1957 w. R. POSTLEWAlTE ET AL 3,3133% Aprii l 1 CONDUCTOR CASING FOROFFSHORE DRILLING AND WELL COMPLETION 5 Sheets-Sheet 1 Filed April 1,1964 FIGW INVENTORS WILL/AM R. POSTLEV/A/TE MILTON LUDW/G FIGZ Aprii111, 1967 w. R. POSTLEWAITE ET AL 3,313,358

CONDUCTOR CASING FOR OFFSHORE DRILLING AND WELL COMPLETION Filed April1, 1964 HHI IfT I E I IIH Hill I II 5 Sheets-Sheet 2 INV E NTORS WILL/AMR. POSTLEWA/TE MILTON LUDW/G Apxrfi M, 1967 w. R. POSTLEWAITE ET AL3,313,358

CONDUCTOR CASING FOR OFFSHORE DRILLING AND WELL COMPLETION 5Sheets-Sheet 5 Filed April 1, 1964 INVE NT 0 RS WILL/AM R. POSTLEWA/TEMILTON LUpW/G TRNES FlG.7A

w. R. POSTLEWAITE ET AL 3,313,353

OFFSHORE DRILLING AND WELL COMPLETION 5 Sheets-Sheet 4 April 11, 2%?

CONDUCTOR CASING FOR Filed April 1, 1964 /6; 767 WK Ml FIGIIO lNVENTORSW/LL/AM R. POSTLEWA/TE Aprii H, 1%? w. R. POSTLEWAITE ET AL 3,313,358

CONDUCTOR CASING FOR OFFSHORE DRILLING AND WELL COMPLETION Filed April1, 1964 5 Sheets-Sheet FIG.

INVENTORS W/LL/AM R. POSTLEWA/TE MILTON LUDW/G BY 2% LALLSZQ UnitedStates Patent 3,313,358 CONDUCTQR CASING FOR OFFSHORE DRHLLING AND WELLCOMPLETION William R. Postlewaite, Menlo Park, and Milton Ludwig,

Berkeley, Calif., assignors to Chevron Research Company, a corporationof Delaware Filed Apr. 1, E64, Ser. No. 356,461 5 Claims. (Cl. 1757)This invention relates to drilling in earth formations located beneath abody 'of water, particularly deep, open water such as an ocean. Morespecifically, this invention relates to a method and apparatus forpreventing bending and buckling of a drilling fluid conductor casing inoffshore drilling and well completion, which casing extends from theocean floor to a drilling platform at the ocean surface.

In recent years it has become desirable in some circumstances to conductoffshore drilling operations from a floating vessel rather than from arigid structure or a platform support from the ocean bottom. In suchoperations the floating vessel is sometimes connected to the well borein the submerged formation by a long tubular member through whichdrilling and well working tools, drilling fluid, etc., pass between thevessel and the well bore. This long tubular member will hereinafter becalled a conductor casing or riser.

In one procedure for offshore drilling the lower end of the conductorcasing is connected to a wellhead, which includes blowout preventors andcontrol equipment, while the upper end of the casing is connected to thedrilling vessel. The wellhead is designed to remain stationary on theocean floor. The drilling vessel, on the other hand, is continuouslymoving under the action of tides, currents, waves and wind. Movement ofthe vessel is somewhat restricted by anchoring and by specialpositioning systems. But, the violent and constantly changing forcesacting on the vessel often shift it from its position over the well boreby lateral distances in excess of four percent of the water depth.Experience has shown that vertical heaving movements of up to 25 feet atvelocities of three to four feet per second can also be expected inaddition to the relatively slower vertical movement effected by tides.One accepted method of allowing for the relative lateral and verticalmovement between the vessel and the wellhead is to place laterallyflexible joints and telescopic joints in the conductor casing. Thispermits the conductor casing to accommodate the movement of the vesselwithin design limits.

As drilling operations were carried on in deeper water, it was foundthat the conductor casing itself tended to deflect or bend along itslength between the flexible joints. This bending has often been so greatthat structural failure of the conductor casing column has resulted.Even when failure does not occur. bending is undesirable if it resultsin a sharp angle in the casing at any point along its length, therebycausing dilficulty in passing drill pipe, well casing, etc. This problemis particularly acute where the flexible or universal joint must beincluded in the casing near its lower end to allow for vessel movement.Since bending moments are not transmitted through such a joint, anybending of the conductor casing tends to create a sharp angle at thisjoint. When using a ball and socket joint. for example. an angle greaterthan five degrees at the joint makes it very diflicult to pass the drillstring through the joint. The tendency toward angularity at the loweruniversal joint is accentuated by vessel movement laterally from itsposition over the wellhead.

In analyzing the causes of the extreme lateral deflection of theconductor casing, it is appro riate to consider the casing as a longtubular column. When drilling in deep water the length of this columnbecomes so great as compared to the moment of inertia of its crosssectional area that the casing has virtually no column stiffness. Thusany axial compression or lateral forces will cause severe deflection orbending of the conductor casing.

If the conductor casing is supported solely at its lower end, its owneffective weight, i.e., weight in water, causes it to be in axialcompression, increasing from Zero at the top to a maximum at the bottomsupport. When drilling in deep water the compressive stress in thecasing wall from this source alone is sufficient to buckle the casing.Friction in the telescopic joint as the vessel moves vertically towardthe ocean bottom as well as drilling or well working tools which maybind on and be supported by the conductor casing as they are passedthrough it add compressive stress to the conductor casing wall andthereby increase the deflection of the casing.

In addition to the buckling effect of the above-mentioned axialcompressive forces which create net compressive stress in the casingwall, current and wave forces acting transversely along the length ofthe conductor casing tend to bend it. Although wave forces decreaseexponentially with depth below the surface, recent submarinemeasurements have shown that they extend deep enough to be a substantialfactor in bending the conductor casing. Also strong current forces havebeen found at substantial depths. For convenience in discussion thesecurrent and wave forces will be called environmental forces. It shouldbe noted that since they act generally transverse to the conductorcasing length they do not create a net axial compression in the casingwall at any cross-section but create a tensile force in one diametricalhalf of the section which is equal and opposite to the compressive forcein the other half.

The types and magnitudes of the various forces, such as those discussedabove, which create net axial compression in the casing wall as well asthe environmental forces which act generally transverse to the casinglength vary under different operating conditions. The prior artrecognizes the existence of these forces and has sought to overcometheir effect by applying enough axial tension to the conductor casing tocompensate for the weight of it and to counteract the bending caused bythe transverse environmental forces.

In water depths up to approximately 250 feet satisfactory results haveusually been obtained by applying tension sufficient only to compensatefor the types of forces discussed above. However, in greater depthsbuckling and excessive bending still occur when this method is employed.The offshore drilling industry has been unable to determine the cause ofthis and has suffered large financial losses as a result.

It has now been discovered that the buckling that has been repeatedlyexperienced with deep water risers is a result of the high density ofthe drilling fluid in the conductor casing. Although the difference indensity between the drilling fluid and the surrounding sea water doesnot cause a net compressive force to be applied directly to theconductor casing, it has a buckling effect on the casing. The proof ofthis, both analytical and experimental, will be discussed below in thedetailed description of this invention.

It also will be proven that in long conductor casings transmitting densedrilling fluid, this effect may be compensated for by applying to theconductor casing, in addition to the tensile forces applied tocompensate for axial compressive forces acting directly on the conductorcasing and the transverse environmental forces as shown by the priorart, an extra tensile force in an amount calculated in accordance withformulas developed in this specification to compensate for the bendingeffect of the dense drilling fluid.

Several alternative arrangements of concentrated floats,

elongated buoyant members, and a concentrated bottom end counterweightare provided for applying the desired tension. Two alternative types oftelescopic joint and a cable and pulley arrangement for connecting theupper end of the conductor casin to the vessel are also provided. Theseserve also to reduce the direct compressive buckling forces transmittedfrom the moving vessel to the conductor casing.

The operation and advantages of the method and apparatus of thisinvention will be clear from the following detailed description.Throughout this description reference will be made to the accompanyingdrawings in which:

FIGURE 1 is an overall elevation view of apparatus of this invention inoperating position.

FIGURE 2 is an enlarged view of portions of FIG- URE 1.

FIGURE 3 is a schematic diagram showing the effect of axial compressionon a column.

FIGURE 4 is a schematic illustration of the effect of axial compressionon a fluid filled tubular column.

FIGURE 5 is an elevation view of the upper end of the conductor casingabove the telescopic joint and its connection to the vessel.

FIGURE 6 is a sectional view along lines 66 of FIGURE 5.

FIGURE 7A is an elevation view of the upper portion of the telescopicjoint of this invention with portions shown in section for clarity.7AFIGURE 7B is a downward continuation of FIGURE FIGURE 8 is a sectionalview along line 8-8 of FIGURE 7A with portions removed for clarity.

FIGURE 9 is a sectional view along line 9-9 of FIGURE 7B.

FIGURE 10 is a vertical elevation in section through a portion of theconductor casing.

FIGURE 11A is an elevation view of the upper portion of a modified formof the telescopic joint of this invention, with portions removed forclarity.

FIGURE 11B is downward continuation of FIGURE 11A.

FIGURE 12 is a sectional view along line 12-12 of FIGURE llB.

Referring to FIGURES 1 and 2,.vessel 1 is floating on a body of water 2such as an ocean. The vessel includes a vertical opening 3 through itshull near the longitudinal and transverse center of the vessel.Supported on the upper deck. 4 of the vessel and approximately centeredover the opening 3 is a derrick structure 5 from which the upper end ofdrill pipe 8 is supported by a traveling block 9 and swivel 10. Thederrick structure and much of the associated equipment are of a typecommonly used in offshore rotary drilling and are not shown in detail.Approximately centered in the base of the derrick are a platform 6 androtary table 7. The drill pipe 8 passes vertically through alignedopenings in the platform and rotary table and is rotated by the rotarytable 7 in a standard manner. Anchors connected to anchor chains 12 and13 limit the movemelrltt of the vessel from its normal position over thewe A wellhead is located on the submerged formation 11 in which the holeis being drilled. The wellhead includes a base 21, and stacked blowoutpreventers 22 and 23 which are releasably connected to the base bycoupling 24. Several lengths of well casing 27 and 28 extend beneath thewellhead into the well. At least two guideposts and 26 extend verticallyfrom spaced points near the circumference of base 21. Guide lines 29 and30 extending from guideposts 25 and 26, respectively, to the vessel 1are used to guide equipment as it is lowered from the vessel to thewellhead. These guide lines extend upward through the opening 3 in thebottom of the vessel, over pulleys 31 and 32, and are connected at theirupper ends to constant tension winches 33 and 34 respectively. Thesewinches maintain the guide lines taut in spite of relative movementbetween vessel 1 and wellhead 20. Guide arms 35 and 36 extend outwardlyfrom coupling 24 and include guide sleeves near their outer ends. Afterthe base 21 with its guideposts 25 and 25 and guide lines 29 and 30 arein place, the blowout preventer assembly including coupling 24 may belowered from the vessel with a guide line passing through each guidesleeve to position the assembly as shown. The coupling and blowoutpreventers are remotely actuable from the vessel by fluid under pressurefrom lines 37, 38, and 39 which extend to the vessel through tubing 40.

With the wellhead in place on the ocean bottom the conductor casing maybe lowered to connect the floating vessel to the wellhead. Thisconductor casing is releasably connected at its lower end to thewellhead by coupling and is connected at its upper end to the vessel ina manner which will be described below. The heavy coupler 45 is pendantbelow the universal ball joint 43. Guide arms 46 and 47 are aligned onthe center of 48 so that the connection at coupler 45 is assured and isindependent of the angularity of the conductor casing. The conductorcasing includes a ball and socket joint 48 near its lower end and aflexible member 49 near its upper end to permit angular movement of thecasing relative to vertical, and to reduce the torsional stresstransmitted to the wellhead and to the upper connection of the casing atthe vessel as the vessel shifts laterally from its posi tion over thewell under the action of wind, tides, waves, and currents. Belowflexible member 49, the conductor casing includes a telescopic joint 50which permits axial elongation and shortening of the casing as thevessel moves laterally and vertically.

The major portion of the conductor casing consists of a series ofelongated tubular conductor members 51 connected end to end by couplings52 to extend from telescopic joint 50 to ball and socket joint 48. Theupper end of the conductor casing is flared out at 54 for receiving thedrill pipe and other equipment which passes through the connectorcasing.

High density drilling fluid is fed to the well from a sump on thevessel. The drilling fluid passes through flexible hose 55, down througha passageway in the axis of the drill pipe, and out bit 56 at the bottomof the well. The drilling fluid is returned to the sump by passingupwardly around the outside of the drill pipe through well casing 28 and27, through wellhead 20 and then upward through the conductor casing.The drilling fluid is returned to a sump through pipe 57 which isflexibly connected to the conductor casing near its upper end.

Axial forces applied to a confined liquid tend to deflect the confiningpipe. Referring to the example in FIGURE 4 there is shown a longitudinalcross-section through a length of tubular steel pipe 6t) filled with aliquid 61. The pipe is extremely long in comparison with its diameter sothat it acts as a long column with a large slenderness ratio. Portionsof its length have been omitted for convenience in the drawings. Theends of the pipe 60 are sealed by slidable pistons 62 and 63 which arefree to move axially along the pipe 69. Each piston includes a pivotbearing 64 on its outer face. A clamp 65 including a screw member 66 isdesigned to exert pressure between stationary face 67 of the clamp andmovable face 68 of the screw. The pressure is transmitted through thepistons 62 and 63 to the fluid 61, which is substantiallyincompressible. Hence the effect is similar to placing end loading on asolid column. A sufficiently great force placed on bearing 64 bytightening of the screw 66 will cause the pipe 60 to buckle from itsoriginal straight position. The deflection of the pipe is indicated bythe letter a. It is apparent that as the slenderness ratio of the pipe60 becomes greater, less force is required to buckle the pipe since itacts as a long column. Thus it can be seen that compressive forceapplied to a liquid confined in an elongated tubular member causesflexing and buckling of the tubular member in the same manner ascompressive forces applied to a solid long column.

The above phenomenon has been repeatedly substan tiated by actualinstances of conductor casing failure where the effect of the drillingfluid was not accounted for. Also experiments have been conducted usinga small scale model of a conductor casing. In these experiments a longsteel tube of small diameter was supported only at its top (to removeany compressive stress from the weight of the tube itself) and filledwith mercury. The weight of the mercury was supported by a plug at thebottom. The plug was slidable axially along the tube. Under theseconditions the loading of the mercury imposed on the tube was similar tothat of drilling fluid on a conductor casing. The deflection of the tubeunder such loading was completely consistent with the above analysis.

Practical application of the above analysis to a conductor casing inoffshore drilling requires consideration of the conditions to which theconductor casing -is subjected. As was pointed out above, the wave andcurrent forces as well as the forces created by vessel movement arecontinuously varying within large parameters. While the magnitude ofthese forces may be calculated and determined experimentally, any suchdetermination is necessarily only an approximation due to the naturallyvarying and complex nature of these forces. Therefore it is desirable toadd a safety factor in the form of extra tension.

Another practical consideration is that in offshore drilling operationsin deep water the conductor casing is extremely long in comparison withthe moment of inertia of its cross-section so that it may be consideredto have virtually no column stiffness. Thus, even in the absence oflateral environmental forces, it will not withstand any substantial netaxial compressive force throughout a substantial portion of its lengthwithout undesirably large deflection and possible structural failure.While in the absence of lateral environmental forces, the conductorcasing could theoretically withstand some axial compressive force overrelatively short increments of its length, for practical purposes, andto insure safe operation, it is preferred to assume that the net axialcompressive force must equal zero or preferably be negative, i.e.,tensile rather than compressive, throughout the length of the conductorcasing, and then to add an overpull, or additional tensile force, tolimit the deflection from the environmental forces.

For convenience it may be preferable to express the net axialcompressive force as it applies to conductor casings in offshoredrilling as: the net axial compressive force acting on any transversecross-section is equal to the weight in water of the column of drillingfluid above that section, plus the weight in water of the conductorcasing column above that section, plus any other axial compressiveforces applied directly to the conductor casing above that section. Thisrelationship is based on the assumption that the pressure of thedrilling fluid is zero at the top of the column and that its pressureincreases linearly with depth in proportion to its weight. While notprecisely true in all cases this form of the equation is generallyadequate to arrive at a practical determination of the forces involvedin a riser used for offshore drilling.

Still another force which may cause buckling of the conductor casingduring drilling and well working operations is created by compressivestress incurred by material such as well casing which is being passedaxially through the conductor casing. If the well casing becomes boundagainst the interior wall of the conductor casing so that the wellcasing weight is supported on the conductor casing, the compressivestress S in the conductor casing wall will be increased. If, instead,the well casing becomes supported from below, such as against the sidesof the well bore, the well casing will develop compressive stress in itsown walls. The well casing, if of great length,

will have virtually no column stiffness. Thus the transverse force ofthe buckled well casing will be imposed on the wall of the riser. Adrill pipe in axial compression would have a similar effect. In order todesign for the worst conditions which may be encountered, it isdesirable to incorporate these forces in the design.

The generic relationship for the net axial compressive force may beconveniently stated as: the net axial compressive force tending to bendor buckle the conductor casing at any transverse cross section is equalto the algebraic sum of all the axial forces acting on the Walls of theconductor casing at that section and all the axial forces acting on allmaterials within the conductor casing at that section minus the productof pressure of the sea water outside that section times the externalarea of the conductor casing.

As pointed out heretofore, it is undesirable to have a sharp angle atthe ball joint located at the bottom of the conductor casing. As thevessel moves laterally from a position over the wellhead, the weight ofthe materials contained in the riser accentuates this angle because theweight develops a moment about the ball joint. This angle can becontrolled by the amount of overpull added to the conductor casing.

The relationship between the amount of overpull and the angle at anypoint along the riser may be determined from wherein -F=the verticalcomponent of net axial force.

Since the lateral movement of the vessel is small relative to the lengthof the conductor casing, the axial component of the vertical force F issubstantially equal to the vertical force F and may be assumed to be thesans As a specific example of application of the above analysis to aconductor casing, it will be assumed that operations are to be carriedon in Water 600 feet deep with a 13% OD. x /8" pipe as the conductorcasing, and drilling fluid weighing pounds per cubic foot being the onlymaterial in the casing.

The maximum force P will occur at the lower end of the conductor casing.it will be approximately equal to the Weight in water of the entireconductor casing column (27,100 pounds), plus the weight in water of theentire volume of drilling fluid contained in the conductor casing(29,200 pounds), giving a total P of 56,300 pounds. Thus an upward forcein excess of this amount is required.

If the operations are to be carried on from a floating vessel which willbe displaced laterally from a position over the wellhead, for example,by twenty-four feet, and assuming normal current forces, the angle ofthe riser at the ball joint can be limited to five degrees by anoverpull of 20,300 pounds. This overpull is an upward force in additionto the 56,300 pounds required to reduce F to zero. Further overpull canbe added as a safety factor and/ or to account for friction in thetelescopic joint.

Having determined the magnitude of tensile stress to be applied to thecasing in accordance with the procedure discussed above, tensile forcemay be applied to the conductor casing in any of several manners. Forexample an upward force can be applied through cables connected at theirone end to the conductor casing and at their other end either to one ormore constant tension winches located on the vessel, or to weightssuspended over pulleys mounted on the vessel. However, the preferredapparatus of this invention uses one or more submerged buoyant membersattached to the conductor casing for applying the desired upward force.This eliminates the problems inherent in pulling on the casing from thevessel which is continuously moving relative to the major portion of theriser.

In view of the magnitude of the upward force imposed on the riser toachieve the result of this invention, a counteracting downward force isnecessary to prevent the riser from being pulled out of the water. Theweight in water of the conductor casing opposes the upward force but isinsufficient to completely counteract it. Additional downward force maybe applied, for example, through cables connected at their one end tothe conductor casing and at their other end either anchored to the oceanfloor, or connected to submerged buoyant members through pulleys whichare anchored on the ocean floor. Alternatively the wellhead andassociated equipment may be relied on to either completely or partiallycounteract the upward force, either by its weight, or by weights addedto the wellhead, or by anchoring the wellhead or the well casing whichis suspended from it to the submerged formation. In order to avoidreliance on anchors and the possibility of damaging the wellheadequipment by transmitting substantial tensile stress through it, thepreferred apparatus of this invention uses a large weighted mass orcounterweight connected to the bottom end of the riser.

Referring to FIGURES 1 and 2, which illustrate an embodiment of theinvention, a large buoyant member or float 94 is connected around theconductor casing to apply a relatively large upward force concentratedat one location on the casing. The buoyancy of the illustrated float isconstant, but can be made adjustable by known modifications.

FIGURE 10 illustrates another embodiment of the invention wherein abuoyant member for applying upward force to the conductor casing isdistributed uniformly along a substantial portion of the casing length.Each of the tubular conductor members 51 which form the major portion ofthe conductor casing is surrounded by a larger diameter sealed shellmember 95. A conical member 180 connects the lower end of each conductormember 51 to the lower end of the associated shell member 95. Similarlya conical member 103 connects the upper end of each conductor member 51to the upper end of the associated shell member 95. A sealed chamber 96is thus formed bounded by conductor member 51, shell member 95, andconical members 10!} and 16-3. Chamber 96 is filled with air, or someother material less dense than the surrounding sea water, to exert anupward buoyant force on tubular member 51.

Each shell member 95 includes an annular collar 97 at its lower end andan annular collar 98 at its upper end. A clamp 99 of a type commonlyused in oil well drilling cooperates with shoulders 101 and 102 oncollars 97 and 98 respectively to connect the conductor members 51 inend-to-end relationship. Ring seals 196 and 167 in flanges 97 and 98respectively prevent loss of drilling fluid through the connectionbetween adjacent outer shell members.

When drilling at great depths, it is preferable to use high pressure airor gas in chamber 96 in order to safeguard against collapsing of thewalls of shell members 95 under the external pressure of the sea water.Discs 108 connected between conductor member 51 and shell member ataxially spaced intervals aid in preventing collapse of the shell memberand also increase the column stiffness of the conductor casing 'bymaking the shell and the casing act as a single unit.

Referring again to FIGURE 2 a toroidal concentrated mass orcounter-weight surrounds ball joint 48 and has its center of gravity atthe center of the ball joints rotation. It is connected to the lower endof the conductor casing by rigid steel gusset plates 111 and 112 toposition it centrally relative to the center of the ball joint. Thecounter-weight thus exerts a downward force at the lower end of theconductor casing. Since the center of mass of the counter-weightcoincides with the center of rotation of the ball and socket joint 48,the counterweight exerts no bending moment about the ball and socketjoint even when the conductor casing is inclined from the vertical.

Several arrangements of the above described concentrated float 9% and/ordistributed buoyant shell 95 are used alternatively in conjunction withthe concentrated counter-weight 110 to apply the desired tensile forcesto the conductor casings. In one such arrangement one or more largefloats 90 are located immediately below telescopic connector 50, andprovide the entire desired upward force. This upward force is opposed bythe weight of the conductor casing and concentrated mass 11th acting onthe bottom of the conductor casing. In some instances it may bedesirable to rely on the wellhead and associated equipment which isanchored to the submerged formation for providing a portion of thedownward force. In a second alternative the buoyant shell 95 isconnected along the entire length of the conductor casing between thetelescopic connector and the bottom ball and socket joint to provide auniformly distributed upward force of a total magnitude equal to thatdesired. In this arrangement the tensile stress in the conductor casingis at a minimum near the upper end of the conductor casing where thecompressive force of the drilling fluid is also at a minimum, and is ata maximum near the lower end of the conductor casing where the bucklingforce is at a maximum. This alternative eliminates the problem ofhandling a large submerged float and also reduces the effective areasubjected to the large ocean current and wave forces which exist nearthe ocean surface.

Other alternative methods use at least one concentrated float 99 incombination with distributed buoyant shells 95. For example, aconcentrated float is connected to the con-ductor casing at a depth ofapproximately feet where the current and wave forces are substantiallyreduced. The concentrated float is proportioned so as to provide anupward buoyant force equal to the maximum net axial compressive forceapplied at the transverse section where the float is located plusthe'desired overpull to reduce the bending effect of the transverseenvironmental forces to within design limits. Upward force is applied tothe portion of the conductor casing above the concentrated float eitherby use of a second concentrated float immediately below the telescopicjoint or alternatively by use of a shell member along that portion ofthe conductor casing. In such an arrangement the portion of theconductor casing above the first concentrated float acts as a separatesystem from that portion below the conccntrated float insofar as bendingof the conductor casing relative to vertical is concerned.

Still another arrangement includes a shell member connected to theconductor casing substantially along its entire length but proportionedso as to provide only a portion of the upward force desired. One or moreconcentrated floats are then connected to the conductor casing toprovide the remainder of the desired upward force. Thus the diameter ofthe concentrated floats is reduced, thereby reducing the problems ofwave force and handling.

Many other arrangement may be used to obtain the desired tensile stressin the conductor casing as contemplated by the above analysis ofbuckling and bending forces, as

will be obvious from the teaching of the above disclosure.

Reference is now made to FIGURES 9 in conjunction with the descriptionof the telescopic joint and support for the upper end of the conductorcasing,

It is imperative that this joint be constructed in a manner which willreduce to a minimum the frictional load transmitted through it to theconductor casing string below it, and also in a manner to preventbinding of the joint as the vessel moves vertically toward the oceanbottom.

The uppermost of the casing members 51 in the conductor casing string isdesignated 51a. It is surrounded by cylindrical shell a (FIGURE 7B) andterminates a substantial axial distance below the upper end of shell95a. A ring 12!) is connected to the upper end of conductor member 51aand to the inner surface of shell 95a to seal the upper end of chamber96. Conductor member 121 is of a smaller outer diameter than the innerdiameter of conductor member 51a and extends into member 51a intelescopic relationship. The upper end of conductor member 121 issupported from the floating vessel in a manner which will be describedbelow. Thus as the floating vessel moves vertically relative to thewellhead, conductor member 121 moves vertically with it and relative toconductor member 51a and shell 95a.

A slide bearing arrangement is provided between conductor members 51::and 121 to prevent binding during relative axial sliding movement. Thisbearing arrangement is housed in cylindrical casing 125 which has anoutside diameter substantially equal to the inside diameter of shell95a. Thus casing 125 fits snugly in the upper end of shell 95a with thelower end of casing 125 resting on ring 129. A plug 126 is threaded intothe upper end of shell 95a to retain casing 125 in place. The plug isremovable for access to the hearings in casing 125. A hearing 129 of lowfriction material slidably engages the outer wall of conductor member121 and rests on shoulder 128 of sleeve 127 which is connected to theinterior of casing 125 near the upper end of the casing. Bearing 129maintains the upper end of shell 95a concentric with conductor member121. Near the lower end of casing 125 a second bearing 138, similar tohearing 129 slidably engages conductor member 121. Bearing 130 is surrounded by sleeve 131 and rests on shoulder of sleeve 131. An outersleeve 132 surrounds sleeve 131 and includes a shoulder 138 at its upperend which abuts internal shoulder 133 of casing 125. The upper end ofsleeve 131 abuts shoulder 138. The lower end of outer sleeve 132 extendsdown beyond the lower end of sleeve 131 and is connected to ring 134.Ring 134 is connected to the inner Wall of casing 125. Pressure actuatedlip type rubber packings 148 and 143 surround conductor member 121 toprevent drilling fluid from escaping upward around conductor member 121where the abrasive cuttings would destroy guide bearings 129 and 132. Apair of retainer rings 137 and 141 include upward annular protrusions139 and 142 respectively which are wedged into grooves or lips in thelower face of seal packings 148 and 143. A removable ring 136 isthreaded into ring 134 to retain bearing 130, and packing seals and 143in place. As ring 136 is tightened, its upper face forces lip spreaderring 137 axially toward shoulder 135 and annular protrusions 139 and 142in turn hold packings 140 and 143, which have a natural garter action tohug in tight engagement with conductor member 121. Bearing 130 maintainsthe upper end of conductor member 51a concentric with member 121.

Rigidly connected around the upper portion of conductor 121 is a discshaped plate 150. Suspended from plate 158 is a tubular member 151 whichhas an internal diameter larger than the external diameter of shell 95aand surrounds the shell in telescopic relationship. The lower end oftubular member 151 extends slightly below the lower end of conductormember 121. Intermediate the ends of member 151 two axially spacedring-shaped plates 152 and 153 are rigidly connected around member 151.These plates are connected to each other by four pairs of spaced plates154-155, 156-157, 158159, and 160- 161 (FIGURE 9). A wheel 166 isrotahly mounted on an axle 163 which extends between plates 158 and 159.The wheel has a concave surface which bears against the outer surface ofshell 951: through an opening in the wall of tubular member 151. Wheels167, 168 and 169 are similarly mounted between the other pairs ofplates. Braces such as 172 connected between tubular member 151 andplate member 153 add rigidity to the structure. As conductor member 121and appended shell 151 move axially relative to conductor member 51acausing the associated tubular member 151 to move relative to shell 95a,wheels 166469 will roll along shell 95a and maintain shell 95a andtubular member 151 in concentric relationship. A similar four wheelbearing arrangement is designated generally by the numeral 178 in FIGURE78 and is located at the lower end of tubular member 151.

A nipple 171 extends through plate 150 and directs a flow of liquid suchas water through nozzle 171 onto conductor member 121 to act as alubricant during the telescopic motion. Bearings 129 and 131 eachinclude longitudinal grooves which permit the lubricant to pass throughthem.

The means for connecting the upper end of the conductor casins to thefloating vessel will be described with reference to FIGURES 2, 5, 6, and7A. A steel plate 180 (FIGURE 5) is connected to the under side ofplatform 6 of the vessel in parallel relation thereto. Plate 188includes a circular opening in its center which is coextensive with theopening in platform 6 through which the drill pipe 8 is passed. Bracingmembers 181 and 182 of FIGURE 6 are arranged so as not to interfere withpassing of the drill pipe through the opening. A pulley 183 is mountedon the under side of plate 180 for rotation about an axle 184 which isperpendicular to the plane of plate 188. A pair of pulleys 185 and 186are supported from the bottom of plate 180 in housings 187 and 183respectively, for rotation about horizontal axles 189 and 190respectively, each of which is parallel to the plane of plate 189. Oneend of a cable 191 is connected by clevis 194 to bracket 192. The cableextends upward over pulley 185, around pulley 183 and over pulley 186down to a bracket 193 to which the opposite end of the cable isconnected by clevis 194. Brackets 192 and 193 are connected to the topof shell 95a. Pulleys 183, 185, and 186 are arranged so that the portionof cable 191 between pulley 185 and pulley 186 will lie substantially ina single plane parallel to plate 188. As is clear from FIGURE 6, the twovertical portions of cable 191 are diametrically opposed relative to theopening in plate 188. The portion of cable 191 between pulley 186 andbracket 193 passes freely through a hole 196 in a discshaped steel plate197 which is connected around conductor member 122. A coil spring 198surrounds cable 191, the upper end of spring 198 normally abutting thelower face of plate 197 and the lower end of spring 198 normallyabutting a collar 199 which is adjustably fixed to cable 191 by clamp288. The initial tension on spring 198 may be adjusted by turning screw201 which moves sleeve 199 along cable 191. A short cylindrical sleeve202 retains the upper end of spring 198 in concentric relationship withcable 191. The lower end of spring 198 is held in concentricrelationship with cable 191 by collar 199. A similar spring and clamparrangement is located on the portion of cable 191 between pulley 185and bracket 192. Plate 197 is braced to tubular member 122 by triangularmembers 283 and 204. This support ing arrangement permits limitedmovement of the upper end of the conductor casing relative to theplatform 6, but springs 198 bias the upper portion of the conductorcasing to its normal position vertically below the opening in theoperating platform.

Referring to FIGURES 2, 7A, and 8, brackets 210 and 211 are connected totubular member 151 and spaced approximately 120 around the circumferenceof tubular member 151 on opposite sides of bracket 193. Cables 212, 213,and 214 are connected to brackets 193, 210, and 211, respectively byswivel joints 215, 216, and 217 respectively. Cables 212, 213, and 214extend radially from the tubular member 151 each to a swivel connectionwith the vessel structure to restrain the upper end of members 121 and151 in a position approximately aligned with the opening in platform 6.Safety cables 218 and 219 are swivelly connected to brackets 193 and 192respectively and extend downwardly and outwardly there from to points ofconnection on the structure of the vessel. These safety cables serve tolimit the upward movement of the upper end of the conductor casingrelative to platform 6 and the vessel.

FIGURES 11A, 11B, and 12 illustrate a modified form of telescopic joint.As in the joint of FIGURES 7A and 7B, in FIGURES 11A and 11B, theconductor member 121 is slidably inserted into conductor member 51a. Lowfriction bearing 225 is connected to the lower end of conductor member121. Bearing 225 provides a tight seal to prevent loss of mud aroundconductor member 121, and also maintains the lower end of conductormember 121 in concentric relationship with conductor member 51a. Asecond bearing 225 connected to the interior of conductor member 51anear the top of the conductor member tightly surrounds member 121 toprovide a second seal and to maintain the upper end of member 51:: inconcentric relationship with member 121. A set of four wheels 227, 228,229, and 230 bear on tubular member 51a at circumferentially spacedpoints in a manner similar to wheels 160469 of the telescopic joint ofFIG- URES 7A and 7B. Four Wheels 231 bear on the circumference oftubular member 51a at a point axially spaced below wheels 227-230 in amanner similar to the arrangement 170 of FIGURE 7A and 7B. The eightwheels are connected to the upper end of conductor member 121 through anopen framework which includes eight spaced apart members 232, 233, 234,235, 23s, 237, 238, and 239, each of which extend in a directionparallel to the axis of conductor member 121. These eight members areconnected together at their bottoms by plate 240 and are braced togetherintermediate their lengths by rings 241, 242, and 243-. The tops of theeight members are connected by circular plate 244 which surrounds and isrigidly connected to the upper end of conductor member 121.

The telescopic joint of FIGURES 7A and 7B is shown.

in combination with a conductor casing member 51a which includes a shell95a around it, while the conductor casing shown in combination with thetelescopic joint of FIGURES 11A and 11B does not include a shell. Thisdifference is for purposes of illustration only and each of the jointsis easily modifiable for use with either type of casing member.

These and other modifications will be obvious from the above teachingsand the invention described herein should be limited only by thefollowing claims.

We claim:

1. A conductor casing for connecting a wellhead on the ocean bottom to avessel floating on the ocean surface substantially vertically above thewellhead comprising: an elongated tubular member containing a drillingfluid denser than water, said member having its lower end connected to afixed wellhead adjacent the ocean floor and its upper end connected to afloating vessel, means near the lower end of said member for permittinguniversal angular movement of the axis of said member relative to saidwellhead, means near the upper end of said member for permittinguniversal angular movement of the axis of said member relative to saidfloating vessel, means in the upper portion of said member permittingaxial elongation and contraction of said member, means for exerting anupward force on said member, a mass operatively connected to said memberadjacent its lower end for resisting said upward force, said mass andsaid upward force exerting means being proportioned with respect to eachother and said member so that the longitudinal compressive force exertedby the drilling fluid in said member does not exceed the longitudinaltensile force exerted on said member throughout any substantial portionof the length of said member.

2. A conductor casing for connecting a Wellhead fixed on the oceanbottom to a vessel floating substantially vertically above the wellheadcomprising: an elongated tubular member containing a dense drillingfluid, said member having its lower end connected to said wellhead andits upper end connected to said floating vessel, means near the lowerend of said member for permitting universal angular movement of the axisof said member relative to said wellhead, means near the upper end ofsaid member for permitting universal angular movement of the axis ofsaid member relative to said floating vessel, means in the upper portionof said member permitting axial elongation of said member, a massconnected to said member near its lower end for exerting a downwardforce on said member, buoyant means aflixed to said member at a pointintermediate its ends, said buoyant means being proportioned to exert afirst upward force on said member in excess of the weight in water ofthe portion of said member below said buoyant means plus the weight inwater of the dense drilling fluid contained'in that portion, meansexerting a second upward force on the portion of said member above saidbuoyant means, said second force being in excess of the weight in waterof the portion of said member above said buoyant means plus the weightin water of the drilling fluid contained therein, and said concentratedmass being proportioned to exert a downward force on said membersubstantially equal in magnitude to the total of said first and secondupward forces minus the weight in water of said member.

3. A conductor casing as recited above in claim 2 wherein said means forexerting a second upward force comprises a second buoyant means aflixedto said conductor casing and distributed substantially uniformly alongthe length of the portion of said member above said first buoyant means.

4. For use in offshore drilling from a floating vessel, means forconnecting the upper end of a conductor casing to the floating vesselcomprising: a cable one end of which is pivotally connected to theconductor casing at a first point and the other end of which ispivotally connected to said conductor casing at a second point, saidfirst and second points each being below the top of said conductorcasing and circumferentially spaced from each other, first and secondpulleys connected to said floating vessel, each of said pulleys having ahorizontal axis of rotation, said cable extending upward from said firstpoint over said first pulley, across from said first pulley over saidsecond pulley, and downward from said second pulley to said secondpoint, the upward and downward extending portions of said cable eachbeing substantially parallel to said conductor casing axis, guide meansconnected to said conductor casing through which means said upward anddownward extending portions pass, and resilient means connected to eachof said upward and downward extending portions, each of said resilientmeans bearing against said guide means to yieldably resist movement ofsaid cable through said guide means.

5. For use in offshore drilling and well working from a floating vessel,an elongated tubular conductor comprising an elongated lower tubularmember, an elongated upper tubular member, means for fixing the lowerend of said lower member relative to and adjacent the submarine earthformation, means for connecting the upper end of said upper member tosaid floating vessel, said upper member and said lower member beingproportioned so that one of said members nests in the other of said members in telescopic relationship throughout a portion of its length toform a continuous conduit at all positions of said vessel relative tosaid submarine formation With selected design limits and means formaintaining the nested portion of said members in axial alignment witheach other and for reducing friction between said members as saidmembers move axially relative to each other, said last recited meanscomprising first bearing means connected to one of said members and insl-idable engagement with the other of said members, second bearingmeans connected to one of said members at a location axially spacedalong said members from said first bearing means and in slidableengagement With the other of said members, a frame structure connectedto the inner one of said members at a location axially spaced from thenested portion of said member and extending axially along said member insurrounding relationship with the nested portions of said upper andlower members, and third and fourth axially spaced bearing means formaintaining said frame structure in axial alignment with the outer oneof said members.

References Cited by the Examiner UNITED STATES PATENTS References Citedby the Applicant UNITED STATES PATENTS McNeill. Stokes.

Voorhees; Tucker. Willis et a1. Rhodes et a1.

ERNEST R. PURSER, Primary Examiner.

1. A CONDUCTOR CASING FOR CONNECTING A WELLHEAD ON THE OCEAN BOTTOM TO AVESSEL FLOATING ON THE OCEAN SURFACE SUBSTANTIALLY VERTICALLY ABOVE THEWELLHEAD COMPRISING: AN ELONGATED TUBULAR MEMBER CONTAINING A DRILLINGFLUID DENSER THAN WATER, SAID MEMBER HAVING ITS LOWER END CONNECTED TO AFIXED WELLHEAD ADJACENT THE OCEAN FLOOR AND IS UPPER END CONNECTED TOAFLOATING VESSEL, MEANS NEAR THE LOWER END OF SAID MEMBER FOR PERMITTINGUNIVERSAL ANGULAR MOVEMENT OF THE AXIS OF SAID MEMBER RELATIVE TO SAIDWELLHEAD, MEANS NEAR THE UPPER END OF SAID MEMBER FOR PERMITTINGUNIVERSAL ANGULAR MOVEMENT OF THE AXIS OF SAID MEMBER RELATIVE TO SAIDFLOATING VESSEL, MEANS IN THE UPPER PORTION OF SAID MEMBER PERMITTINGAXIAL ELONGATION AND CONTRACTION OF SAID MEMBER, MEANS FOR EXERTING ANUPWARD FORCE ON SAID MEMBER, A MASS OPERATIVELY CONNECTED TO SAID MEMBERADJACENT ITS LOWER END FOR RESISTING SAID UPWARD FORCE, SAID MASS ANDSAID UPWARD FORCE EXERTING MEANS BEING PROPORTIONED WITH RESPECT TO EACHOTHER AND SAID MEMBER SO THAT THE LONGITU-